UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-12295
GENESIS ENERGY, L.P.
(Exact name of registrant as specified in its charter)
Delaware 76-0513049
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
500 Dallas, Suite 2500, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 860-2500
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
-------- --------
This report contains 21 pages
2
GENESIS ENERGY, L.P.
Form 10-Q
INDEX
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements Page
----
Consolidated Balance Sheets - June 30, 2000 and December 31, 1999 3
Consolidated Statements of Operations for the Three and Six
Months Ended June 30, 2000 and 1999 4
Consolidated Statements of Cash Flows for the Six Months
Ended June 30, 2000 and 1999 5
Consolidated Statement of Partners' Capital for the Six
Months Ended June 30, 2000 6
Notes to Consolidated Financial Statements 7
Item 2.Management's Discussion and Analysis of Financial Condition
and Results of Operations 14
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 21
Item 6. Exhibits and Reports on Form 8-K 21
3
GENESIS ENERGY, L.P.
CONSOLIDATED BALANCE SHEETS
(In thousands)
June 30, December 31,
2000 1999
-------- --------
ASSETS (Unaudited)
CURRENT ASSETS
Cash and cash equivalents $ 5,674 $ 6,664
Accounts receivable -
Trade 447,513 241,529
Related party - 7,030
Inventories 515 404
Insurance receivable for pipeline spill costs 7,000 16,586
Other 10,689 2,504
-------- --------
Total current assets 471,391 274,717
FIXED ASSETS, at cost 116,675 116,332
Less: Accumulated depreciation (25,839) (22,419)
-------- --------
Net fixed assets 90,836 93,913
OTHER ASSETS, net of amortization 11,297 11,962
-------- --------
TOTAL ASSETS $573,524 $380,592
======== ========
LIABILITIES AND PARTNERS' CAPITAL
CURRENT LIABILITIES
Short-term debt $ 21,000 $ 19,900
Accounts payable -
Trade 437,622 251,742
Related party 13,352 1,604
Accrued liabilities 18,157 19,290
-------- --------
Total current liabilities 490,131 292,536
COMMITMENTS AND CONTINGENCIES (Note 8)
ADDITIONAL PARTNERSHIP INTERESTS 8,700 3,900
MINORITY INTERESTS 30,428 30,571
PARTNERS' CAPITAL
Common unitholders, 8,625 units issued and
8,617 units and 8,620 units outstanding at
June 30, 2000 and December 31, 1999,
respectively 43,444 52,574
General partner 864 1,051
-------- --------
Subtotal 44,308 53,625
Treasury Units, 8 units and 5 units at June 30,
2000 and December 31, 1999, respectively (43) (40)
-------- --------
Total partners' capital 44,265 53,585
-------- --------
TOTAL LIABILITIES AND PARTNERS' CAPITAL $573,524 $380,592
======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
4
GENESIS ENERGY, L.P.
STATEMENTS OF OPERATIONS
(In thousands, except per unit amounts)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
2000 1999 2000 1999
---------- -------- ---------- --------
REVENUES:
Gathering and marketing revenues
Unrelated parties $1,161,271 $483,404 $2,159,701 $853,777
Related parties 29,820 25,638 29,820 34,892
Pipeline revenues 3,805 4,346 7,218 8,442
---------- -------- ---------- --------
Total revenues 1,194,896 513,388 2,196,739 897,111
COST OF SALES:
Crude costs, unrelated parties 1,124,027 467,287 2,081,523 833,204
Crude costs, related parties 60,598 34,856 95,379 42,273
Field operating costs 3,197 2,958 6,411 5,610
Pipeline operating costs 2,032 1,966 4,085 3,934
---------- -------- ---------- --------
Total cost of sales 1,189,854 507,067 2,187,398 885,021
---------- -------- ---------- --------
GROSS MARGIN 5,042 6,321 9,341 12,090
EXPENSES:
General and administrative 2,720 3,016 5,376 6,039
Depreciation and amortization 2,035 2,064 4,081 4,112
---------- -------- ---------- --------
OPERATING INCOME (LOSS) 287 1,241 (116) 1,939
OTHER INCOME (EXPENSE):
Interest income 47 39 84 69
Interest expense (354) (306) (702) (516)
Gain on asset disposals 32 31 20 900
---------- -------- ---------- --------
INCOME (LOSS) BEFORE MINORITY INTERESTS 12 1,005 (714) 2,392
Minority interests 2 201 (143) 479
---------- -------- ---------- --------
NET INCOME (LOSS) $ 10 $ 804 $ (571) $ 1,913
========== ======== ========== ========
NET INCOME (LOSS) PER COMMON
UNIT - BASIC AND DILUTED $ - $ 0.09 $ (0.06) $ 0.22
========== ======== ========== ========
NUMBER OF COMMON UNITS
OUTSTANDING 8,623 8,604 8,623 8,604
========== ======== ========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
5
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended June 30,
2000 1999
--------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (571) $ 1,913
Adjustments to reconcile net income to net
cash provided by (used in) operating
activities -
Depreciation 3,422 3,408
Amortization of intangible assets 659 704
Minority interests equity in earnings (143) 479
Gain on disposals of fixed assets (20) (900)
Other noncash charges 1,326 746
Changes in components of working capital -
Accounts receivable (198,954) 11,657
Inventories (111) (7,438)
Other current assets 1,401 362
Accounts payable 197,628 (14,039)
Accrued liabilities (2,365) (2,077)
--------- --------
Net cash provided by (used in) operating activities 2,272 (5,185)
--------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment (365) (1,284)
Change in other assets 6 3
Proceeds from sales of assets 40 1,014
--------- --------
Net cash used in investing activities (319) (267)
--------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net borrowings under Loan Agreement 1,100 8,700
Distributions to common unitholders (8,625) (8,603)
Distributions to general partner (176) (176)
Issuance of additional partnership interests 4,800 -
Purchase of treasury units (42) -
--------- --------
Net cash used in financing activities (2,943) (79)
--------- --------
Net decrease in cash and cash equivalents (990) (5,531)
Cash and cash equivalents at beginning of period 6,664 7,710
--------- --------
Cash and cash equivalents at end of period $ 5,674 $ 2,179
========= ========
The accompanying notes are an integral part of these consolidated financial
statements.
6
GENESIS ENERGY, L.P.
CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL
(In thousands)
(Unaudited)
Partners' Capital
-------------------------------------
Common General Treasury
Unitholders Partner Units Total
------- ------ ---- -------
Partners' capital at December 31, 1999 $52,574 $1,051 $(40) $53,585
Net loss for the six months ended June 30, 2000 (560) (11) - (571)
Distributions during the six months ended
June 30, 2000 (8,625) (176) - (8,801)
Purchase of treasury units - - (42) (42)
Issuance of treasury units to Restricted Unit
Plan participants - - 39 39
Excess of expense over cost of treasury units issued
for Restricted Unit Plan 55 - - 55
------- ------ ---- -------
Partners' capital at June 30, 2000 $43,444 $ 864 $(43) $44,265
======= ====== ==== =======
The accompanying notes are an integral part of these consolidated financial
statements.
7
GENESIS ENERGY, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Formation and Offering
In December 1996, Genesis Energy, L.P. ("GELP") completed an initial public
offering of 8.6 million Common Units at $20.625 per unit, representing limited
partner interests in GELP of 98%. Genesis Energy, L.L.C. (the "General
Partner") serves as general partner of GELP and its operating limited
partnership, Genesis Crude Oil, L.P. Genesis Crude Oil, L.P. has two subsidiary
limited partnerships, Genesis Pipeline Texas, L.P. and Genesis Pipeline USA,
L.P. Genesis Crude Oil, L.P. and its subsidiary partnerships will be referred
to collectively as GCOLP. The General Partner owns a 2% general partner
interest in GELP.
Transactions at Formation
At the closing of the offering, GELP contributed the net proceeds of the
offering to GCOLP in exchange for an 80.01% general partner interest in GCOLP.
With the net proceeds of the offering, GCOLP purchased a portion of the crude
oil gathering, marketing and pipeline operations of Howell Corporation
("Howell") and made a distribution to Basis Petroleum, Inc. ("Basis") in
exchange for its conveyance of a portion of its crude oil gathering and
marketing operations. GCOLP issued an aggregate of 2.2 million subordinated
limited partner units ("Subordinated OLP Units") to Basis and Howell to obtain
the remaining operations.
Basis' Subordinated OLP units and its interest in the General Partner were
transferred to its then parent, Salomon Smith Barney Holdings Inc. ("Salomon")
in May 1997. In February 2000, Salomon acquired Howell's interest in the
General Partner. Salomon now owns 100% of the General Partner.
Unless the context otherwise requires, the term "the Partnership" hereafter
refers to GELP and its operating limited partnership.
2. Basis of Presentation
The accompanying consolidated financial statements and related notes present
the financial position as of June 30, 2000 and December 31, 1999 for GELP, the
results of operations for the three and six months ended June 30, 2000 and 1999,
cash flows for the six months ended June 30, 2000 and 1999 and changes in
partners' capital for the six months ended June 30, 2000.
The financial statements included herein have been prepared by the
Partnership without audit pursuant to the rules and regulations of the
Securities and Exchange Commission ("SEC"). Accordingly, they reflect all
adjustments (which consist solely of normal recurring adjustments) which are, in
the opinion of management, necessary for a fair presentation of the financial
results for interim periods. Certain information and notes normally included in
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules and
regulations. However, the Partnership believes that the disclosures are
adequate to make the information presented not misleading. These financial
statements should be read in conjunction with the financial statements and notes
thereto included in the Partnership's Annual Report on Form 10 -K for the year
ended December 31, 1999 filed with the SEC.
Basic net income per Common Unit is calculated on the weighted average number
of outstanding Common Units. The weighted average number of Common Units
outstanding for the three months ended June 30, 2000 and 1999 was 8,623,000 and
8,604,000, respectively. For the 2000 and 1999 six month periods, the weighted
average number of Common Units outstanding was 8,623,000 and 8,604,000,
respectively. For this purpose, the 2% General Partner interest is excluded
from net income. Diluted net income per Common Unit did not differ from basic
net income per Common Unit for any period presented.
3. New Accounting Pronouncements
In November 1998, the Emerging Issues Task Force (EITF) reached a consensus
on EITF Issue 98-10, "Accounting for Energy Trading and Risk Management
Activities". This consensus, effective in the first quarter of 1999, requires
that "energy trading" contracts be marked-to-market, with gains or losses
recognized in current earnings. The Partnership has determined that its
activities do not meet the definition in EITF Issue 98-10 of "energy trading"
activities and, therefore, is not required to make any change in its accounting,
except as
8
EITF 98 -10 relates to written option contracts. EITF 98-10 requires that
all written option contracts be marked-to-market. For the three and six months
ended June 30, 2000, the Partnership recorded unrealized losses of $0.8 million
and $0.6 million, respectively, as a result of marking these contracts to
market. These amounts are included in cost of crude in the statement of
operations.
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities",
was issued in June 1998. This standard was subsequently amended by SFAS 137 and
SFAS 138. This new standard, which the Partnership will be required to adopt
for its fiscal year 2001, will change the method of accounting for changes in
the fair value of certain derivative instruments by requiring that an entity
recognize the derivative at fair value as an asset or liability on its balance
sheet. Depending on the purpose of the derivative and the item it is hedging,
the changes in fair value of the derivative will be recognized in current
earnings or as a component of other comprehensive income in partners' capital.
The Partnership is in the process of evaluating the impact that this statement
will have on its results of operations and financial position. This new
standard could increase volatility in net income and comprehensive income.
4. Business Segment and Customer Information
Based on its management approach, the Partnership believes that all of its
material operations revolve around the gathering, transportation and marketing
of crude oil, and it currently reports its operations, both internally and
externally, as a single business segment. No customer accounted for more than
10% of the Partnership's revenues in any period.
5. Credit Resources
GCOLP has a Guaranty Facility with Salomon, pursuant to a Master Credit
Support Agreement, and a Working Capital Facility with BNP Paribas. GCOLP's
obligations under these facilities are secured by its receivables, inventories,
general intangibles and cash.
Guaranty Facility
Salomon is providing a Guaranty Facility through December 31, 2000, in
connection with the purchase, sale and exchange of crude oil by GCOLP. The
aggregate amount of the Guaranty Facility is limited to $300 million (to be
reduced in each case by the amount of any obligation to a third party to the
extent that such third party has a prior security interest in the collateral).
GCOLP pays a guarantee fee to Salomon of 0.50% of the utilized amount of
outstanding guarantees. This fee will increase after June 30, 2000, to 0.75%.
An additional fee of 1.00% is paid on any amounts in excess of the $300 million
commitment. At June 30, 2000, the aggregate amount of obligations covered by
guarantees was $290 million, including $186 million in payable obligations and
$104 million of estimated crude oil purchase obligations for July 2000.
The Master Credit Support Agreement contains various restrictive and
affirmative covenants including (i) restrictions on indebtedness other than (a)
pre-existing indebtedness, (b) indebtedness pursuant to Hedging Agreements (as
defined in the Master Credit Support Agreement) entered into in the ordinary
course of business and (c) indebtedness incurred in the ordinary course of
business by acquiring and holding receivables to be collected in accordance with
customary trade terms, (ii) restrictions on certain liens, investments,
guarantees, loans, advances, lines of business, acquisitions, mergers,
consolidations and sales of assets and (iii) compliance with certain risk
management policies, audit and receivable risk exposure practices and cash
management practices as may from time to time be revised or altered by Salomon
in its sole discretion.
Pursuant to the Master Credit Support Agreement, GCOLP is required to
maintain (a) Consolidated Tangible Net Worth of not less than $50 million, (b)
Consolidated Working Capital of not less than $1 million after exclusion of bank
debt from current liabilities, (c) a ratio of its Consolidated Current
Liabilities to Consolidated Working Capital plus net property, plant and
equipment of not more than 7.5 to 1, (d) a ratio of Consolidated Earnings before
Interest, Taxes, Depreciation and Amortization to Consolidated Fixed Charges of
at least 1.75 to 1 as of the last day of each fiscal quarter prior to December
31, 1999 and (e) a ratio of Consolidated Total Liabilities to Consolidated
Tangible Net Worth of not more than 10.0 to 1 (as such terms are defined in the
Master Credit Support Agreement).
9
An Event of Default could result in the termination of the Guaranty
Facility at the discretion of Salomon. Significant Events of Default include
(a) a default in the payment of (i) any principal on any payment obligation
under the Guaranty Facility when due or (ii) interest or fees or other amounts
within two business days of the due date, (b) the guaranty exposure amount
exceeding the maximum credit support amount on the first day of the month for
two consecutive calendar months, (c) failure to perform or otherwise comply with
any covenants contained in the Master Credit Support Agreement if such failure
continues unremedied for a period of 30 days after written notice thereof and
(d) a material misrepresentation in connection with any loan, letter of credit
or guarantee issued under the Guaranty Facility. Removal of the General Partner
will result in the termination of the Guaranty Facility and the release of all
of Salomon's obligations thereunder. The Partnership exceeded the $300 million
maximum credit limitation under the Guaranty Facility on May 1 and June 1, 2000,
due primarily to the rise in crude oil prices and additional outstanding
guarantees. A waiver of the resulting Event of Default was obtained from
Salomon.
There can be no assurance of the availability or the terms of credit for
the Partnership. At this time, Salomon does not intend to provide guarantees or
other credit support after the credit support period expires in December 31,
2000. Upon approval of a proposed restructuring discussed in Note 10, Salomon
will extend the expiration date of its credit support obligation to the
Partnership from December 31, 2000, to December 31, 2001, on the current terms
and conditions. If the General Partner is removed without its consent,
Salomon's credit support obligations will terminate. In addition, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions. Management of the Partnership
intends to replace the Guaranty Facility with a letter of credit facility with
one or more third party lenders prior to December 2000 and has had preliminary
discussions with banks about a replacement letter of credit facility. The
General Partner may be required to reduce or restrict the Partnership's
gathering and marketing activities because of limitations on its ability to
obtain credit support and financing for its working capital needs. The General
Partner expects that the overall cost of a replacement facility may be
substantially greater than what the Partnership is incurring under its existing
Master Credit Support Agreement. Any significant decrease in the Partnership's
financial strength, regardless of the reason for such decrease, may increase the
number of transactions requiring letters of credit or other financial support,
make it more difficult for the Partnership to obtain such letters of credit,
and/or may increase the cost of obtaining them. This situation could in turn
adversely affect the Partnership's ability to maintain or increase the level of
its purchasing and marketing activities or otherwise adversely affect the
Partnership's profitability and Available Cash.
Working Capital Facility
On June 6, 2000, GCOLP entered into a credit agreement ("Credit Agreement")
with BNP Paribas to replace the Loan Agreement with Bank One. The Credit
Agreement provides for loans or letters of credit in the aggregate not to exceed
the lesser of $35 million or the Borrowing Base (as defined in the Credit
Agreement). The maximum amount the Credit Agreement will be reduced from $35
million to $25 million if BNP Paribas fails to assign loan commitments to other
lenders by September 7, 2000. Interest is calculated, at the Partnership's
option, by using either LIBOR plus 1.4% or BNP Paribas' prime rate minus 1%.
The Credit Agreement expires on the earlier of (a) February 28, 2003 or (b)
30 days prior to the termination of the Master Credit Support Agreement with
Salomon. As the Master Credit Support Agreement terminates on December 31,
2000, the Credit Agreement with BNP Paribas will expire on November 30, 2000.
See Note 10 for a discussion on the conditions under which Salomon may extend
the Master Credit Support Agreement. Should those conditions occur, the Credit
Agreement with BNP Paribas will automatically extend to November 30, 2001.
The Credit Agreement is collateralized by the accounts receivable, inventory,
cash accounts and margin accounts of GCOLP, subject to the terms of an
Intercreditor Agreement between BNP Paribas and Salomon. There is no
compensating balance requirement under the Credit Agreement. A commitment fee
of 0.35% on the available portion of the commitment is provided for in the
agreement. Material covenants and restrictions include the following: (a)
maintain a Current Ratio (calculated after the exclusion of debt under the
Credit Agreement from current liabilities) of 1.0 to 1.0; (b) maintain a
Tangible Capital Base (as defined in the Credit Agreement) in GCOLP of not less
than $65 million; and (c) maintain a Maximum Leverage Ratio (as defined in the
Credit Agreement) of not more than 5.0 to 1.0. Additionally the Credit
Agreement imposes restrictions on the ability of GCOLP to sell its assets, incur
other indebtedness, create liens and engage in mergers and acquisitions. The
10
Partnership was not in compliance with the covenant regarding a Maximum
Leverage Ratio at June 30, 2000. A waiver for the period was obtained from BNP
Paribas.
At December 31, 1999, and June 30, 2000, the Partnership had $19.9 million
and $21.0 million, respectively, of outstanding debt. The Partnership had no
letters of credit outstanding at June 30, 2000. At June 30, 2000, $14 million
was available to be borrowed under the Credit Agreement.
Distributions
Generally, GCOLP will distribute 100% of its Available Cash within 45 days
after the end of each quarter to Unitholders of record and to the General
Partner. Available Cash consists generally of all of the cash receipts less
cash disbursements of GCOLP adjusted for net changes to reserves. A full
definition of Available Cash is set forth in the Partnership Agreement.
Distributions of Available Cash to the holders of Subordinated OLP Units are
subject to the prior rights of holders of Common Units to receive the minimum
quarterly distribution ("MQD") for each quarter during the subordination period
(which will not end earlier than December 31, 2001) and to receive any
arrearages in the distribution of the MQD on the Common Units for prior quarters
during the subordination period. MQD is $0.50 per unit.
Salomon has committed, subject to certain limitations, to provide total
cash distribution support with respect to quarters ending on or before December
31, 2001, in an amount up to an aggregate of $17.6 million in exchange for
Additional Partnership Interests ("APIs"). Salomon's obligation to provide
distribution support will end no later than December 31, 2001 or until the $17.6
million is fully utilized, whichever comes first.
Through June 30, 2000, the Partnership utilized $8.7 million of the
distribution support from Salomon. On August 14, 2000, the Partnership will
utilize an additional $2.6 million of distribution support for the distribution
related to the second quarter. After the distribution in August 2000, $11.3
million of distribution support has been utilized and $6.3 million remains
available through December 31, 2001, or until such amount is fully utilized,
whichever comes first. See Note 10 for additional information regarding a
proposed restructuring which could affect distribution support. APIs purchased
by Salomon are not entitled to cash distributions or voting rights. The APIs
will be redeemed if and to the extent that Available Cash for any future quarter
exceeds the amount necessary to distribute the MQD on all Common Units and
Subordinated OLP Units and to eliminate any arrearages in the MQD on Common
Units for prior periods.
In addition, the Partnership Agreement authorizes the General Partner to
cause GCOLP to issue additional limited partner interests and other equity
securities, the proceeds from which could be used to provide additional funds
for acquisitions or other GCOLP needs.
6. Transactions with Related Parties
Sales, purchases and other transactions with affiliated companies, in the
opinion of management, are conducted under terms no more or less favorable than
those conducted with unaffiliated parties.
Sales and Purchases of Crude Oil
A summary of sales to and purchases from related parties of crude oil is as
follows (in thousands).
Six Months Six Months
Ended Ended
June 30, June 30,
2000 1999
------- -------
Sales to affiliates $29,820 $34,892
Purchases from affiliates $95,379 $42,273
General and Administrative Services
The Partnership does not directly employ any persons to manage or operate
its business. Those functions are provided by the General Partner. The
Partnership reimburses the General Partner for all direct and indirect costs of
11
these services. Total costs reimbursed to the General Partner by the
Partnership were $8,408,000 and $8,542,000 for the six months ended June 30,
2000 and 1999, respectively.
Guaranty Facility
As discussed in Note 5, Salomon provides a Guaranty Facility to the
Partnership. For the six months ended June 30, 2000 and 1999, the Partnership
paid Salomon $749,000 and $312,000, respectively, for guarantee fees under the
Guaranty Facility.
7. Supplemental Cash Flow Information
Cash received by the Partnership for interest was $76,000 and $70,000 for the
six months ended June 30, 2000 and 1999, respectively. Payments of interest
were $835,000 and $500,000 for the six months ended June 30, 2000 and 1999,
respectively.
8. Contingencies
The Partnership is subject to various environmental laws and regulations.
Policies and procedures are in place to monitor compliance. The Partnership's
management has made an assessment of its potential environmental exposure and
determined that such exposure is not material to its consolidated financial
position, results of operations or cash flows. As part of the formation of the
Partnership, Basis and Howell agreed to be responsible for certain environmental
conditions related to their ownership and operation of their respective assets
contributed to the Partnership and for any environmental liabilities which Basis
or Howell may have assumed from prior owners of these assets.
The Partnership is subject to lawsuits in the normal course of business and
examination by tax and other regulatory authorities. Additionally, litigation
involving the Partnership has been filed related to the proposed restructuring.
See Note 10. Such matters presently pending are not expected to have a material
adverse effect on the financial position, results of operations or cash flows of
the Partnership.
As part of the formation of the Partnership, Basis and Howell agreed to each
retain liability and responsibility for the defense of any future lawsuits
arising out of activities conducted by Basis and Howell prior to the formation
of the Partnership and have also agreed to cooperate in the defense of such
lawsuits.
Pipeline Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi and entered a creek nearby. Some of the
oil then flowed into the Leaf River.
The Partnership responded to this incident immediately, deploying crews to
evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing maintenance and reduced clean-up
activity expected to continue for an undetermined period of time.
The estimated cost of the spill clean-up is expected to be $18 million.
This amount includes estimates for clean-up costs, ongoing maintenance and
settlement of potential liabilities to landowners in connection with the spill.
The incident was reported to insurers. At June 30, 2000, $15.4 million had been
paid to vendors and claimants for spill related costs, and $2.6 million was
included in accrued liabilities for estimated future expenditures. Current
assets included $3.3 million of expenditures submitted and approved by insurers
but not yet reimbursed, $1.1 million for expenditures not yet submitted to
insurers and $2.6 million for expenditures not yet incurred or billed to the
Partnership. At June 30, 2000, $11.0 million in reimbursements had been
received from insurers.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be reimbursed by
insurance. At this time, it is not possible to predict whether the Partnership
will be fined, the amounts of such fines or whether the governmental agencies
would prevail in imposing such fines.
12
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of the
system. At this time, it is unknown whether there will be any required testing
or changes and the related cost of that testing or changes.
If Management of the Partnership determines that the costs of testing or
changes are too high, that segment of the system may not be restarted. If this
part of the Mississippi System is taken out of service, the net book value of
that portion of the pipeline would be written down to its net realizable value,
resulting in a non-cash write-off of approximately $6.0 million. Tariff
revenues for this segment of the system in the year 1999 were $0.6 million.
Crude Oil Contamination
In February and March 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels of oil in the pipeline. The north end of the Texas pipeline system has
been temporarily shut down but is expected to be operational by the end of the
third quarter of 2000. As of June 30, 2000, the estimated volume of crude that
was potentially contaminated had been reduced to 21,000 barrels.
The Partnership has accrued costs associated with transportation, testing
and consulting in the amount of $188,000, of which $32,000 has been paid at June
30, 2000. The potentially contaminated barrels are reflected in inventory at
their cost of approximately $0.6 million.
The Partnership has recorded a receivable for $188,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has provided the Partnership with evidence that it has sufficient resources to
cover the total expected damages incurred by the Partnership. Management of the
Partnership believes that it will recover any damages incurred from the third
party.
9. Distributions
On July 14, 2000, the Board of Directors of the General Partner declared a
cash distribution of $0.50 per Unit for the quarter ended June 30, 2000. The
distribution will be paid August 14, 2000, to the General Partner and all Common
Unitholders of record as of the close of business on July 31, 2000. The
Subordinated OLP Unitholders will not receive a distribution for the quarter.
This distribution will be paid utilizing approximately $1.8 million cash
available from the Partnership and $2.6 million cash provided by Salomon
pursuant to Salomon's Distribution Support Agreement.
10. Proposed Restructuring
On May 10, 2000, the Partnership announced that based on the recommendation
of the Special Committee appointed by the General Partner, the General Partner
and the Board of Directors of the General Partner of the Partnership unanimously
approved a financial restructuring of the Partnership. The proposal for a
financial restructuring of the Partnership is subject to approval by holders of
a majority of the Partnership's outstanding public common units. Assuming
unitholder approval, the proposed restructuring is expected to be effective
beginning with distributions for the third quarter of 2000. Under the terms of
the restructuring, the partnership agreement of GCOLP will be amended to:
- eliminate without the payment of any consideration all of the
outstanding subordinated limited partner units in our operating partnership;
- terminate the subordination period and, as a result, eliminate the
requirement that the common limited partnership units accrue arrearages;
- eliminate without the payment of any consideration all of the
outstanding additional limited partner interests, or APIs, issued to Salomon
in exchange for its distribution support and, as a result, eliminate our
obligation to redeem the APIs issued to Salomon in exchange for its
distribution support;
13
- reduce the quarterly distribution from the current $0.50 per unit to a
targeted $0.20 per unit; and
- reduce the respective thresholds that must be achieved before the
general partner is entitled to incentive distributions from the current
threshold levels of $0.55, $0.635 and $0.825 to the new threshold levels of
$0.25, $0.28 and $0.33 per unit.
If the proposal is approved:
- Salomon will contribute to the operating partnership the unused
distribution support expected to be $6.3 million. After payment of
transaction costs associated with the restructuring estimated at $1.3
million, we will then declare a special distribution in the aggregate amount
of $5.0 million, or $0.58 per unit.
- Salomon will extend the expiration date of its credit support obligation
to the partnership from December 31, 2000 to December 31, 2001 on the current
terms and conditions.
In connection with the proposal for restructuring, the Partnership is
preparing a proxy statement to be mailed to all of the Partnership's public
unitholders that will contain a more detailed description of the proposal.
On June 7, 2000, Bruce E. Zoren, a holder of units of limited partner
interests in the Partnership, filed a putative class action complaint in the
Delaware Court of Chancery, No. 18096-NC, seeking to enjoin the restructuring
and seeking damages. Defendants named in the complaint include the Partnership,
Genesis Energy L.L.C., members of the board of directors of Genesis Energy,
L.L.C., and the owner of Genesis Energy L.L.C. The plaintiff alleges numerous
breaches of the duties of care and loyalty owed by the defendants to the
purported class in connection with making a proposal for restructuring.
Management of the Partnership believes that the complaint is without merit and
intends to vigorously defend the action.
14
GENESIS ENERGY, L.P.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Genesis Energy, L.P., operates crude oil common carrier pipelines and is an
independent gatherer and marketer of crude oil in North America, with operations
concentrated in Texas, Louisiana, Alabama, Florida, Mississippi, New Mexico,
Kansas and Oklahoma. The following review of the results of operations and
financial condition should be read in conjunction with the Consolidated
Financial Statements and Notes thereto.
Results of Operations
Selected financial data for this discussion of the results of operations
follows, in thousands, except barrels per day.
Three Months Ended June 30, Six Months Ended June 30,
2000 1999 2000 1999
-------- -------- -------- --------
Gross margin
Gathering and marketing $ 3,269 $ 3,941 $ 6,208 $ 7,582
Pipeline $ 1,773 $ 2,380 $ 3,133 $ 4,508
General and administrative expenses$ 2,720 $ 3,016 $ 5,376 $ 6,039
Depreciation and amortization $ 2,035 $ 2,064 $ 4,081 $ 4,112
Operating income (loss) $ 287 $ 1,241 $ (116) $ 1,939
Interest income (expense), net $ (307) $ (267) $ (618) $ (447)
Barrels per day
Wellhead 101,702 88,985 101,977 88,614
Bulk and exchange 361,973 263,187 325,775 268,026
Pipeline 92,493 95,590 90,333 92,190
Gross margins from gathering and marketing operations are a function of
volumes purchased and the difference between the price of crude oil at the point
of purchase and the price of crude oil at the point of sale, minus the
associated costs of aggregation and transportation. The absolute price levels
of crude oil do not necessarily bear a relationship to gross margin because
absolute price levels normally impact revenues and cost of sales by equivalent
amounts. As a result, the impact of period-to-period price variations on
revenues and cost of sales generally are not meaningful in analyzing the
variations in gross margins, and such changes are not addressed in the following
discussion.
Pipeline gross margins are primarily a function of the level of throughput
and storage activity and are generated by the difference between the regulated
published tariff and the fixed and variable costs of operating the pipeline.
Changes in revenues, volumes and pipeline operating costs, therefore, are
relevant to the analysis of financial results of the Partnership's pipeline
operations.
The price level of crude oil impacts gathering and marketing and pipeline
gross margins to the extent that oil producers adjust production levels. Short-
term and long-term price trends impact the amount of cash flow that producers
have available to maintain existing production and to invest in new reserves,
which in turn impacts the amount of supply that is available to be gathered and
marketed by the Partnership and its competitors.
Six Months Ended June 30, 2000 Compared with Six Months Ended June 30, 1999
Gross margin from gathering and marketing activities was $6.2 million for
the six months ended June 30, 2000, as compared to $7.6 million for the six
months ended June 30, 1999. The decrease of $1.4 million represents the net
effect of several factors.
Wellhead, bulk and exchange purchase volumes for the six months ended June
30, 2000, increased 20 percent from the same period in 1999. This rise resulted
in a $1.5 million increase in gathering and marketing gross
15
margins. The gain was partially offset by a 9 percent decline in the
average difference between the price of crude oil at the point of purchase and
the price of crude oil at the point of sale, which reduced gross margin by $0.8
million. Also contributing to the decline in gross margin were a $0.6 million
unrealized loss on written option contracts (see Note 3 to the financial
statements), a $0.7 million increase in the cost of credit and a $0.8 million
increase in field operating costs. The $0.7 million increase in credit costs is
a function of the increase in purchase volumes and an 88 percent increase in the
absolute price level of crude oil. The increase in field operating costs was
primarily from a $0.3 million increase in payroll and benefits costs and a $0.4
million increase in fuel costs.
Pipeline gross margin declined $1.4 million, from $4.5 million for the six
month period in 1999 to $3.1 million for the six month period in 2000. Average
tariff revenues declined approximately $0.05 per barrel, which reduced gross
margin by $0.8 million. Additionally, revenues for the 1999 period included
tank storage fees of $0.6 million.
General and administrative expenses decreased $0.7 million between the 2000
and 1999 six month periods. This decline is attributable to decreases in the
following areas: $0.2 million in salary and benefits, $0.1 million in
restricted unit expense and $0.1 million each in professional services and
travel and entertainment. Additionally, the 1999 six month period included
costs related to the Year 2000 remediation totaling $0.2 million.
Depreciation and amortization was flat between the two six month periods.
The Partnership had no material property acquisitions or dispositions that would
create a material fluctuation in depreciation.
In the 2000 six month period, the Partnership incurred net interest expense
of $0.6 million. In the 1999 period, the Partnership incurred net interest
expense of $0.4 million. The increase in interest cost in 2000 was due to the
combination of higher market interest rates and higher interest rates under the
BNP Paribas Working Capital Facility than under the prior facility.
Additionally, average daily outstanding debt during the 2000 period was $2.6
million greater.
Three Months Ended June 30, 2000 Compared with Three Months Ended
June 30, 1999
Gross margin from gathering and marketing activities was $3.3 million for
the three months ended June 30, 2000, as compared to $3.9 million for the three
months ended June 30, 1999. The decrease of $0.6 million represents the net
effect of several factors.
Wellhead, bulk and exchange purchase volumes for the three months ended
June 30, 2000, increased 32 percent from the same period in 1999. This rise
resulted in a $1.3 million increase in gathering and marketing gross margins.
The gain was partially offset by a 9 percent decline in the average difference
between the price of crude oil at the point of purchase and the price of crude
oil at the point of sale, which reduced gross margin by $0.5 million. Also
contributing to the decline in gross margin were a $0.8 million unrealized loss
on written option contracts (see Note 3 to the financial statements), a $0.3
million increase in the cost of credit and a $0.2 million increase in field
operating costs. The $0.3 million increase in credit costs is a function of the
increase in purchase volumes and a 65 percent increase in the absolute price
level of crude oil. The increase in field operating costs was primarily from
increases in payroll and benefits costs and fuel costs.
Pipeline gross margin was $1.8 million for the three months ended June 30,
2000, as compared to $2.4 million for the three months ended June 30, 1999. The
$0.6 million decrease in gross margin can be primarily attributed to a $0.03 per
barrel decline in average tariff revenues, which reduced gross margin by $0.3
million, and a 4 percent decline in throughput, which resulted in a $0.2 million
decline in gross margin. Additionally, pipeline operating costs increased $0.1
million.
General and administrative expenses declined $0.3 million in the three
months ended June 30, 2000 as compared to the same period in 1999. The primary
factors in this decline were a decrease in salaries and benefits, restricted
unit expense and Year 2000 remediation costs of $0.1 million each.
Interest costs were slightly higher in the 2000 quarter due primarily to
higher interest rates.
16
Hedging Activities
Genesis routinely utilizes forward contracts, swaps, options and futures
contracts in an effort to minimize the impact of market fluctuations on
inventories and contractual commitments. Gains and losses on forward contracts,
swaps and future contracts used to hedge future contract purchases of unpriced
crude oil, where firm commitments to sell are required prior to establishment of
the purchase price, are deferred until the margin from the hedged item is
recognized. The Partnership recognized net losses of $1.5 million and $1.2
million for the six months and three months ended June 30, 2000, respectively,
and net gains of $2.0 million and $0.9 million for the six and three months
ended June 30, 1999, respectively, related to its hedging activity.
Liquidity and Capital Resources
Cash Flows
Cash flows provided by operating activities were $2.3 million for the six
months ended June 30, 2000. In the 1999 six-month period, cash flows utilized
in operating activities were $5.2 million. The change between the two periods
results primarily from an increase in inventories in the 1999 period and
variations in the timing of payment of crude purchase obligations.
For the six months ended June 30, 2000 and 1999, cash flows utilized in
investing activities were $0.3 million. In 2000, the Partnership expended $0.4
million for property and equipment additions related primarily to pipeline
operations. In 1999, the Partnership added $1.3 million of assets, primarily
for pipeline operations, and received proceeds of $1.0 million from the sale of
surplus tractors and trailers.
Cash flows used in financing activities by the Partnership during the first
six months of 2000 totaled $2.9 million. Distributions paid to the common
unitholders and the general partner totaled $8.8 million. The Partnership
borrowed $1.1 million under its Working Capital Facility and received $4.8
million from the issuance of APIs to Salomon. In the 1999 period, cash flows
used in financing activities totaled $0.1 million. The Partnership obtained
funds by borrowing $8.7 million. Distributions to the common unitholders and
the general partner totaled $8.8 million.
Working Capital and Credit Resources
As discussed in Note 5 of the Notes to Condensed Consolidated Financial
Statements, the Partnership has a Guaranty Facility with Salomon through
December 31, 2000, and a Credit Agreement with BNP Paribas for working capital
purposes that extends through November 30, 2000. Both of these agreements may
be extended under certain conditions as discussed below under "Proposed
Restructuring". If the General Partner is removed without its consent,
Salomon's credit support obligations will terminate. In addition, Salomon's
obligations under the Master Credit Support Agreement may be transferred or
terminated early subject to certain conditions.
At June 30, 2000, the Partnership's consolidated balance sheet reflected a
working capital deficit of $18.7 million. This working capital deficit combined
with the short-term nature of both the Guaranty Facility with Salomon and the
Credit Agreement with BNP Paribas could have a negative impact on the
Partnership. Some counterparties use the balance sheet and the nature of
available credit support as a basis for determining credit support demanded from
the Partnership as a condition of doing business. Increased demands for credit
support beyond the maximum credit limitations may adversely affect the
Partnership's ability to maintain or increase the level of its purchasing and
marketing activities or otherwise adversely affect the Partnership's
profitability and Available Cash.
Management of the Partnership intends to replace the Guaranty Facility and
Credit Agreement with a working capital letter of credit facility with one or
more third party lenders prior to November 2000. The General Partner expects
that the annual cost of a replacement facility would increase by approximately
$3.3 million.
Increased credit needs and higher credit costs could adversely affect the
Partnership's ability to maintain or increase the level of its purchasing and
marketing activities. Profitability and Available Cash for distributions could
be adversely impacted as well.
17
The Partnership will pay a distribution of $0.50 per Unit for the three
months ended June 30, 2000, on August 14, 2000 to the General Partner and all
Common Unitholders of record as of the close of business on July 31, 2000. The
subordinated OLP Unitholders will not receive a distribution for that period.
This distribution will be paid utilizing approximately $1.8 million of cash
available from the Partnership and $2.6 million of cash provided by Salomon,
pursuant to Salomon's distribution support obligation.
Under the Distribution Support Agreement, Salomon has committed, subject to
certain limitations, to provide cash distribution support, with respect to
quarters ending on or before December 31, 2001, in an amount up to an aggregate
of $17.6 million in exchange for APIs. Salomon's obligation to purchase APIs
will end no later than December 31, 2001, or when the distribution support has
been fully utilized, whichever comes first. . After the distribution in August
2000, $11.3 million of distribution support has been utilized and $6.3 million
remains available through December 31, 2001, or until such amount is fully
utilized, whichever comes first. The Distribution Support Agreement will be
terminated if the proposed restructuring discussed below is approved by a
majority of the Partnership's unitholders.
Proposed Restructuring
On May 10, 2000, the Partnership announced that based on the recommendation
of the Special Committee appointed by the General Partner, the General Partner
and the Board of Directors of the General Partner of the Partnership unanimously
approved a financial restructuring of the Partnership. The proposal for a
financial restructuring of the Partnership is subject to approval by holders of
a majority of the Partnership's outstanding public common units. Assuming
unitholder approval, the proposed restructuring is expected to be effective
beginning with distributions for the third quarter of 2000. Under the terms of
the restructuring, the partnership agreement of GCOLP will be amended to:
- eliminate without the payment of any consideration all of the
outstanding subordinated limited partner units in our operating partnership;
- terminate the subordination period and, as a result, eliminate the
requirement that the common limited partnership units accrue arrearages;
- eliminate without the payment of any consideration all of the
outstanding additional limited partner interests, or APIs, issued to Salomon
in exchange for its distribution support and, as a result, eliminate our
obligation to redeem the APIs issued to Salomon in exchange for its
distribution support;
- reduce the quarterly distribution from the current $0.50 per unit to a
targeted $0.20 per unit; and
- reduce the respective thresholds that must be achieved before the
general partner is entitled to incentive distributions from the current
threshold levels of $0.55, $0.635 and $0.825 to the new threshold levels of
$0.25, $0.28 and $0.33 per unit.
If the proposal is approved:
- Salomon will contribute to the operating partnership the unused
distribution support expected to be $6.3 million. After payment of
transaction costs associated with the restructuring estimated at $1.3
million, we will then declare a special distribution in the aggregate amount
of $5.0 million or $0.58 per unit.
- Salomon will extend the expiration date of its credit support obligation
to the partnership from December 31, 2000 to December 31, 2001 on the current
terms and conditions.
In connection with the proposal for restructuring, the Partnership is
preparing a proxy statement to be mailed to all of the Partnership's public
unitholders that will contain a more detailed description of the proposal.
18
Crude Oil Spill
On December 20, 1999, the Partnership had a spill of crude oil from its
Mississippi System. Approximately 8,000 barrels of oil spilled from the
pipeline near Summerland, Mississippi and entered a creek nearby. Some of the
oil then flowed into the Leaf River.
The Partnership responded to this incident immediately, deploying crews to
evaluate, clean up and monitor the spilled oil. At February 1, 2000, the spill
had been substantially cleaned up, with ongoing maintenance and reduced clean-up
activity expected to continue for an undetermined period of time.
The estimated cost of the spill clean-up is expected to be $18 million.
This amount includes estimates for clean-up costs, ongoing maintenance and
settlement of potential liabilities to landowners in connection with the spill.
The incident was reported to insurers. At June 30, 2000, $15.4 million had been
paid to vendors and claimants for spill related costs, and $2.6 million was
included in accrued liabilities for estimated future expenditures. Current
assets included $3.3 million of expenditures submitted and approved by insurers
but not yet reimbursed, $1.1 million for expenditures not yet submitted to
insurers and $2.6 million for expenditures not yet incurred or billed to the
Partnership. At June 30, 2000, $11.0 million in reimbursements had been
received from insurers.
As a result of this crude oil spill, certain federal and state regulatory
agencies may impose fines and penalties that would not be reimbursed by
insurance. At this time, it is not possible to predict whether the Partnership
will be fined, the amounts of such fines or whether the governmental agencies
would prevail in imposing such fines.
The segment of the Mississippi System where the spill occurred has been
temporarily shut down and will not be returned to service until regulators give
their approval. Regulatory authorities may require specific testing or changes
to the pipeline before allowing the Partnership to restart that segment of the
system. At this time, it is unknown whether there will be any required testing
or changes and the related cost of that testing or changes.
If Management of the Partnership determines that the costs of testing or
changes are too high, that segment of the system may not be restarted. If this
part of the Mississippi System is taken out of service, the net book value of
that portion of the pipeline would be written down to its net realizable value,
resulting in a non-cash write-off of approximately $6.0 million. Tariff
revenues for this segment of the system in the year 1999 were $0.6 million.
Crude Oil Contamination
In February and March 2000, the Partnership purchased crude oil from a
third party that was subsequently determined to contain organic chlorides.
These barrels were delivered into the Partnership's Texas pipeline system and
potentially contaminated 24,000 barrels of oil held in storage and 44,000
barrels of oil in the pipeline. The north end of the Texas pipeline system has
been temporarily shut down but is expected to be operational by the end of the
third quarter of 2000. As of June 30, 2000, the estimated volume of crude that
was potentially contaminated had been reduced to 21,000 barrels.
The Partnership has accrued costs associated with transportation, testing
and consulting in the amount of $188,000, of which $32,000 has been paid at June
30, 2000. The potentially contaminated barrels are reflected in inventory at
their cost of approximately $0.6 million.
The Partnership has recorded a receivable for $188,000 to reflect the
expected recovery of the accrued costs from the third party. The third party
has provided the Partnership with evidence that it has sufficient resources to
cover the total expected damages incurred by the Partnership. Management of the
Partnership believes that it will recover any damages incurred from the third
party.
Current Business Conditions
Changes in the price of crude oil impact gathering and marketing and
pipeline gross margins to the extent that oil producers adjust production
levels. Short-term and long-term price trends impact the amount of cash flow
that producers have available to maintain existing production and to invest in
new reserves, which in turn impacts the amount of crude oil that is available to
be gathered and marketed by the Partnership and its competitors.
19
Although crude oil prices have increased from $12 per barrel in January
1999 to nearly $32 per barrel in June 2000, U.S. onshore crude oil production
volumes have not improved. Further, producers appear to be responding
cautiously to the oil price increase and are focusing more on drilling for
natural gas.
This change is clearly demonstrated by the Baker Hughes North American
Rotary Rig Count for 1997 to 2000.
Baker Hughes North American Rotary Rig Count
Average Number of Rigs Drilling For Crude Oil
Year Oil Gas Price per bbl*
---- --- --- -------------
1997 376 566 $20.60
1998 264 560 $14.40
1999 128 496 $19.25
2000 177 630 $28.80
* Annual average price for 1997 through 1999 and six month average for
2000 for West Texas Intermediate at Cushing, Oklahoma
Based on the limited improvement in the number of rigs drilling for oil,
management of the General Partner believes that oil production in its primary
areas of operation is likely to continue to decrease. Although there has been
some increase since January 1999 in the number of drilling and workover rigs
being utilized in the Partnership's primary areas of operation, management of
the General Partner believes that this activity is more likely to have the
effect of reducing the rate of decline rather than meaningfully increasing
wellhead volumes in its operating areas in 2000.
The Partnership's improved volumes in the first half of 2000 compared to
the same period of 1999 were primarily due to obtaining existing production by
paying higher prices for the production than the previous purchaser. Increased
volumes obtained through competition based on price for existing production
generally result in incrementally lower margins per barrel.
As crude oil prices rise, the Partnership's utilization of, and cost of
credit under, the Guaranty Facility increases with respect to the same volume of
business. The General Partner has taken steps to reduce or restrict the
Partnership's gathering and marketing activities due to the $300 million limit
of the Guaranty Facility.
Additionally, as prices rise, the Partnership may have to increase the
amount of its Credit Agreement in order to have funds available to meet margin
calls on the NYMEX and to fund inventory purchases. No assurances can be made
that the Partnership would be able to increase the size of its Credit Agreement
or that changes to the terms of such increased Credit Agreement would not have a
material impact on the results of operations or cash flows of the Partnership.
Forward Looking Statements
The statements in this Report on Form 10-Q that are not historical
information are forward looking statements within the meaning of Section 27A of
the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. Although the Partnership believes that its expectations regarding future
events are based on reasonable assumptions, it can give no assurance that its
goals will be achieved or that its expectations regarding future developments
will prove to be correct. Important factors that could cause actual results to
differ materially from those in the forward looking statements herein include,
but are not limited to, changes in regulations, the Partnership's success in
obtaining additional lease barrels, changes in crude oil production volumes
(both world-wide as well as in areas in which the Partnership has operations),
developments relating to possible acquisitions or business combination
opportunities, volatility of crude oil prices and grade differentials, the
success of the Partnership's risk management activities, credit requirements by
counterparties of the Partnership, the Partnership's ability to replace its
credit support from Salomon with a bank facility and to replace the working
capital facility from Paribas with another facility, any requirements for
testing or changes to the Mississippi System as a result of the oil spill that
occurred there in December 1999 and conditions of the capital markets and equity
markets during
19
the periods covered by the forward looking statements. All subsequent
written or oral forward looking statements attributable to the Partnership or
persons acting on behalf of the Partnership are expressly qualified in their
entirety by the foregoing cautionary statements.
Price Risk Management and Financial Instruments
The Partnership's primary price risk relates to the effect of crude oil price
fluctuations on its inventories and the fluctuations each month in grade and
location differentials and their effects on future contractual commitments. The
Partnership utilizes New York Mercantile Exchange ("NYMEX") commodity based
futures contracts, forward contracts, swap agreements and option contracts to
hedge its exposure to these market price fluctuations. Management believes the
hedging program has been effective in minimizing overall price risk. At June
30, 2000, the Partnership used futures and forward contracts in its hedging
program with the latest contract being settled in July 2002. Information about
these contracts is contained in the table set forth below.
Sell (Short) Buy (Long)
Contracts Contracts
-------- --------
Crude Oil Inventory:
Volume (1,000 bbls) 7
Carrying value (in thousands) $ 107
Fair value (in thousands) $ 107
Commodity Futures Contracts
Contract volumes (1,000 bbls) 12,724 14,267
Weighted average price per bbl $ 29.11 $ 28.43
Contract value (in thousands) $370,366 $405,565
Fair value (in thousands) $400,760 $445,068
Commodity Forward Contracts:
Contract volumes (1,000 bbls) 6,869 4,895
Weighted average price per bbl $ 30.57 $ 30.59
Contract value (in thousands) $209,991 $149,758
Fair value (in thousands) $221,653 $158,541
Commodity Option Contracts:
Contract volumes (1,000 bbls) 11,430
Weighted average strike price per bbl $ 2.49
Contract value (in thousands) $ 3,278
Fair value (in thousands) $ 3,906
The table above presents notional amounts in barrels, the weighted average
contract price, total contract amount in U.S. dollars and total fair value
amount in U.S. dollars. Fair values were determined by using the notional
amount in barrels multiplied by the June 30, 2000 closing prices of the
applicable NYMEX futures contract adjusted for location and grade differentials,
as necessary.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
See Part I. Item 1. Note 8 to the Condensed Consolidated Financial
Statements entitled "Contingencies", which is incorporated herein by reference.
21
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits.
Exhibit 10 Credit Agreement dated as of June 6, 2000
by and between Genesis Crude Oil, L.P. and BNP Paribas
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K.
A report on Form 8-K was filed on May 12, 2000, announcing the
proposed restructuring of the Partnership.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
GENESIS ENERGY, L.P.
(A Delaware Limited Partnership)
By: GENESIS ENERGY, L.L.C., as
General Partner
Date: August 11, 2000 By: /s/ Ross A. Benavides
----------------------------
Ross A. Benavides
Chief Financial Officer